FLOATING OFFSHORE WIND: COST REDUCTION PATHWAYS TO SUBSIDY FREE - FLOATING OFFSHORE WIND CENTRE OF EXCELLENCE - ORE ...
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FLOATING OFFSHORE WIND CENTRE OF EXCELLENCE FLOATING OFFSHORE WIND: COST REDUCTION PATHWAYS TO SUBSIDY FREE ore.catapult.org.uk 1 ORE.CATAPULT.ORG.UK
CONTENTS
1 INTRODUCTION 4
1.1 Industry engagement 4
2 OUR APPROACH 5
3 INPUT FROM GIS MODEL 6
3.1 Zone analysis and ranking 9
4 UK DEPLOYMENT PROFILES 1O
4.1 Approach to estimating deployment profiles 1O
4.2 Defining the near-term pipeline 1O
4.3 75GW and 1OOGW scenarios 11
4.4 Regional deployment 11
5 KEY COST DRIVERS 12
5.1 Turbine rating 12
5.2 Learning rate 12
5.3 Transmission charges 13
5.4 Cost reduction focus areas 13
5.5 Visible project pipeline 14
6 COST OF CAPITAL 15
6.1 Cost of capital overview 15
7 COST REDUCTION 16
7.1 Cost reduction profile 16
8 CONCLUSIONS 18
9 RECOMMENDATIONS 2O
2 ORE.CATAPULT.ORG.UK
1. INTRODUCTION
Floating offshore wind will play a key role in the UK achieving its net zero
ambition in 2O5O. The scale of this role will be defined by Government
policy and cost reduction in the broader offshore wind industry.
In this report, we aim to map the pathway to subsidy-free floating offshore
wind in the UK. The potential scale of deployment is huge, with a wide
geographic spread of projects in waters around Scotland, Wales, the
South West and North East of England. Based on GIS mapping, we identify
potential zones for floating offshore wind development and establish
deployment profiles that meet, and exceed, targets for Net Zero.
Cost reduction is analysed to assess the impact of uptake of rapidly
developing technology, supply chain competition and decreasing cost of
capital. Based on this analysis, we present a set of recommendations to
support the industry and accelerate cost reduction.
3 ORE.CATAPULT.ORG.UK
1.1 INDUSTRY ENGAGEMENT
A crucial element of this work has been industry engagement. Members
of the Floating Offshore Wind Centre of Excellence have provided
critical input and review. This report has also received detailed input to
assumptions from organisations across the existing and future floating
offshore wind supply chain as well as various financial stakeholders.
We would like to thank the following companies for their input into this study:
// Atkins // JDR Cables
// BAM Nuttall // MHI Vestas Offshore Wind
// First Subsea // Ramboll
// Global Energy Group // Seaway 7
// Green Giraffe // Siemens Gamesa Renewable Energy
// Green Investment Group
The following organisations are the industrial partners in the Floating Offshore
Wind Centre of Excellence…
4 ORE.CATAPULT.ORG.UK
2. OUR APPROACH
The approach adopted for this study has incorporated a combination of GIS
mapping, deployment analysis, bottom-up cost modelling, industry consultation and
learning rate analysis.
The methodology is outlined here and described in detail in the body of this report.
• GIS mapping to identify UK sea areas with highest potential for floating offshore wind
• Refinement of identified areas to create shortlist of zones for early floating offshore wind deployment
• Estimation of deployment potential (in MW capacity) for each shortlisted zone
• Further development of ORE Catapult’s existing bottom-up floating offshore wind cost model
• Supply chain and industry engagement to update modelling technical, cost and financing assumptions
• Use bottom-up cost model to rank shortlisted zones from lowest to highest LCOE
• Generate rational deployment profiles across the shortlisted zones, balancing deploying on the lowest
LCOE sites first with spreading deployment to ensure development activity is distributed to minimise
environmental impacts and maximise the social-economic benefits
• Estimation of learning rates for each key cost centre in DEVEX, CAPEX, OPEX and DECEX
• Identification of drivers and estimation of trajectory for floating offshore wind cost of capital
• Development of Cost Reduction Pathways financial model to combine deployment profiles, site cost
estimates and learning rates
3. INPUT FROM GIS MODEL
UK waters encompassed by the UK Exclusive Economic Zone (EEZ) limit were
considered in the analysis. A wide range of GIS layers were used in the detailed
analysis, with bathymetry being the foremost consideration when selecting sites
appropriate for FOW.
For this study, sites with water depths between 75 – 150m were considered as preferable for early FOW
deployment. Water depths outwith this range are suitable for the technology, however shallower waters will
have to compete with bottom-fixed offshore wind, and deeper water will incur higher costs.
Figure 1 shows the vast areas of UK waters suitable for FOW, highlighted in green. Nine zones were identified
as having preferable site conditions, particularly those with high wind speeds and proximity to a grid connection.
FOW will not be restricted to these zones by any means, but the zones present suitable conditions that we expect
to be representative of near-term UK FOW projects.
These nine zones are shown in Figure 1, marked on the map as zones (denoted A - I).
• Five in Scotland (A, B, C, D & H) – 9.6 GW
• Two in Wales (E & F) – 3.2 GW
• One in NE England (I) – 3.9 GW
• One in SW England (G) – 2.6 GW
In total, this analysis identified a potential near-term pipeline of 19.3GW.
5 ORE.CATAPULT.ORG.UKThe GIS modelling was carried out in reference to the Scottish Government’s draft sectoral marine plan. Since
this work was done, the sectoral marine plan has been finalised with some changes to the development areas
available to offshore wind in Scotwind leasing zones. Zones A, B and H in this report are based on available
Scotwind zones NE8, NE7 and NE1 respectively. All three zones have reduced in size – Zone A by ~ 20%, Zone B
(NE7) by ~ 40% and Zone H by ~ 5%. This change has not been reflected in the modelling done in this study but
would decrease the available capacity at that zone.
The corresponding key site parameters for each of the zones are shown in Table 1. A high-level energy density of
3MW per square kilometre was used to estimate the maximum capacity of each zone. LCOE is based on the cost
estimated today with no learning rate applied.
H
A B
D
C
I
E
F
G
0 70 140 280 Kilometers
© OpenStreetMap (and) contributors, CC-BY-SA
LEGEND CONSTRAINTS
Valid bathymetry range: 75 - 150 m Coordinate System: British National Grid
FOW Deployment Areas [A-I] Mean annual wind speed: > 10 m/s Projection: Transverse Mercator
UK 12 NM Limit (at 150 m altitude) Datum: OSGB 1936
Mean annual significant wave height:3.1 ZONE ANALYSIS AND RANKING
To understand the relative attractiveness of each zone based on cost, a 500MW site using 15MW turbines was
modelled at each zone, reflecting the specific site parameters.
FLOATING WIND ZONE A B C D E F G H I
WINDFARM AREA (km2) 4OO 1,OOO 475 55O 45O 62O 86O 76O 1,3OO
MAX PROJECT CAPACITY
OF ZONE (MW) 1,2OO 3,OOO 1,425 1,65O 1,35O 1,86O 2,58O 2,28O 3,9OO
AVERAGE WATER DEPTH (m) 97.5 11O 1O5 1O7.5 115 1O5 9O 115 95
DISTANCE TO CONSTRUCTION
(ASSEMBLY) PORT (km) 185 2OO 18O 2OO 6O 9O 155 35O 85
DISTANCE TO O&M
(MINOR) PORT (km) 95 1O5 25 65 6O 1OO 85 5O 85
Somerset and North Solway and
GRID CONNECTION ZONE East Aberdeenshire Pembrokeshire Wessex Scotland Cheviot
DISTANCE TO CABLE
LANDFALL (km) 85 95 25 6O 4O 8O 7O 285 4O
ONSHORE CABLE
DISTANCE (km) 5 5 5 5 1O 1O 15 5 5
MEAN WIND SPEED AT SITE
(@ 15OM HEIGHT) (m/s) 11.2 11.2 1O.8 11.15 1O.65 1O.65 1O.4 11.25 1O.1
ANNUAL MEAN SIGNIFICANT
WAVE HEIGHT (m) 2.15 2.15 1.8 2.O5 1.9 2.15 2.2 2.45 1.5
Sand + Sand + Sand +
SEABED CONDITIONS Sand Sand Sand Sand + Gravel Sand Sand
Mud Gravel Mud
ZONE PRIORITY (BASED ON
LCOE) (#) 6 8 2 4 1 5 7 9 3
Table 1: Site parameters for development zones identified with GIS modelling
These parameters impact the following variables:
• Anchor type reflects seabed conditions – gravel seabed requires piles whilst sand may use drag-embedded.
• Mooring line length and chain diameter reflects bathymetry, metocean conditions and turbine size based on
estimated force on the structure
• Vessel operations (Installation and O&M) are impacted by distance to port and estimated weather downtime
driven by metocean conditions
• Transmission system is driven by distance to shore, impacting cable costs and electrical losses
• Grid connection zone affects TNUoS charges, optimised with cable landfall choice
• O&M vessel strategy reflects economic choice dependent on project size, metocean conditions and distance
from O&M port
At the foot of Table 1, the LCOE ranking of lowest cost (ranked 1) to highest cost site (ranked 9) is provided.
Note that Zone H, off Shetland, has the highest LCOE due to the working assumption that it would need to be
connected the mainland GB grid in the timeframe being considered. In the future, where offshore hydrogen
production and other off-grid solutions are being rolled-out, this zone will be more economically viable.
As all the shortlisted sites have high mean wind speeds, ranging from 10.10m/s to 11.25m/s, the two parameters
which have the largest impact on LCOE are the distance to cable landfall, which determines the amount of export
cable required for a project, and the average significant wave height which impacts the frequency of weather
downtime during vessel operations. Excluding Zone H, the highest LCOE is just 13% more expensive than the
lowest LCOE zone.
7 ORE.CATAPULT.ORG.UK4. UK DEPLOYMENT PROFILES
4.1 APPROACH TO ESTIMATING DEPLOYMENT PROFILES
The pace of UK and global FOW deployment will impact the pace of cost reduction and so it is crucial to define
appropriate FOW deployment profiles. Detailed near-term UK FOW profiles based on the GIS-based shortlisting
have been estimated within the context of three UK total offshore wind deployment scenarios: 75GW by 2050;
100GW by 2050; and 150GW by 2050
A single scenario has been assumed for rest of the world (RoW) deployment, reaching 7GW deployed in 2030
(excluding the UK) and 52GW in 2040 (excluding the UK).
4.2 DEFINING THE NEAR-TERM PIPELINE
Based on the priority order established through the initial LCOE assessment, UK deployment profiles out to 2040
were built to reflect the most attractive sites being developed first. The annual and cumulative pictures for these
scenarios are shown in Figure 2.
In the period 2027 – 2031 development has been restricted to zones that are currently available through seabed
leasing, most notably the ongoing Scotwind seabed leasing round which includes zones A and B. Beyond 2031,
the deployment profile has been chosen according to merit order, assuming generally that the lowest LCOE zones
are developed first before moving on to other zones. As each zone has capacity for multiple projects, we have
also ensured geographic diversity to ease pressure on the supply chain and maximise opportunity for economic
and supply chain development. In the 100GW (16GW) scenario, the remaining capacity available within any
individual zone is insufficient for a second large-scale project in 2039. To complete the deployment profile to the
end of the 2030’s, Zone B was selected for a further large-scale site as being representative of site parameters
for a project in 2039 given that by that time Zone B could have been extended or a neighbouring zone identified
and leased.
Project capacity has been optimised to maximise use of transmission assets which have a high proportion of fixed
cost. Balance of system infrastructure is chosen according to site conditions.
Contents
UK FOW Deployment - Scenarios
3.0 20
18
2.5
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GW - cumulative
2.0
GW - annual
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2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
UK 75GW (8GW FOW) - annual UK 100GW (16GW FOW) - annual UK 75GW (8GW FOW) - cumulative UK 100GW (16GW FOW) - cumulative
UK FOW cost Reduction vs BEIS forecast low wholesale price - Scenarios
Figure140
2: UK FOW deployment
120
100
8 ORE.CATAPULT.ORG.UK
Wh (2020)
804.3 75GW AND 1OOGW SCENARIOS
4.3.1 1OOGW
Based on the overall rate of UK offshore wind deployment to meet 100GW by 2050, where we estimate 64GW
by 2040, 16GW of the identified 19.3GW FOW pipeline could be deployed by 2040 with an average annual
deployment rate of 1.3GW per year from 2028 (increasing from 600MW in 2028 through 1.5GW per year by
2035 and up to 3GW per year in 2040).
4.3.2 75GW
The 75GW scenario assumes that similar sites are built out as the 100GW scenario, but with gaps between
projects and increased focus on the sites with lowest LCOE. This leads to installed FOW capacity by 2040 of
8.1GW, at an average annual rate of 730MW per year from 2029.
4.4 REGIONAL DEPLOYMENT
The geographic spread of deployment to 2040 is shown in Figure 3 (8GW FOW) and Figure 4 (16GW FOW).
Several projects marked for deployment in the early 2030s are located in Celtic Sea and North East England. A
seabed leasing round through The Crown Estate within the next two years is needed to unlock access to these
attractive FOW sites. Slower progress in this critical early milestone could jeopardise Net Zero targets and lose
the UK’s early lead in the industry.
H H
A B A B
O.3GW 1.8GW O.9GW 1.8GW
D D 1GW
1.1GW C 1.1GW C
I 2.4GW I 3.9GW
1GW E
1.3GW E
F 1.5GW F 1.5GW
G
2.1GW G
0 70 140 280 Kilometers 0 70 140 280 Kilometers
© OpenStreetMap (and) contributors, CC-BY-SA © OpenStreetMap (and) contributors, CC-BY-SA
Figure 3: 8.1GW of FOW
LEGEND deployment by 2040 in 75GW scenario
CONSTRAINTS Figure 4: 16GW of FOW
LEGEND deployment by 2040 in 100GW
CONSTRAINTS
Valid bathymetry range: 75 - 150 m Coordinate System: British National Grid Valid bathymetry range: 75 - 150 m Coordinate System: British National Grid
FOW Deployment Areas [A-I] Mean annual wind speed: > 10 m/s Projection: Transverse Mercator FOW Deployment Areas [A-I] Mean annual wind speed: > 10 m/s Projection: Transverse Mercator
UK 12 NM Limit (at 150 m altitude) Datum: OSGB 1936 UK 12 NM Limit (at 150 m altitude) Datum: OSGB 1936
Mean annual significant wave height:5. KEY COST DRIVERS
This section outlines our approach to estimating and applying current and future
cost drivers in the bottom-up cost model and the Cost Reduction Pathways model.
5.1 TURBINE RATING
The largest technology cost driver for offshore wind projects is the turbine rating. While global deployment
grows exponentially, we may expect the introduction of larger turbines to accelerate. However, turbine
technology is outpacing the supporting technology required to install it. The industry is at a turning point where
new cranes and vessels need to be developed to withstand the height, reach, and lifting requirements of these
structures, which may slow the pace of advances. The industry may reach a point at which the cost of fabricating
and installing these larger components may outweigh the benefits of larger turbines.
Turbine rating and project capacity increases over time to reflect expected commercial maturity in each
commissioning year and adoption of new technological advances. It has been assumed that 15MW turbines will
be used in UK FOW from around 2030 and 20MW turbines from 2037.
5.2 LEARNING RATE
Learning rates are one of the principal methods to estimate future costs based on precedent either within the
technology, or comparable technologies. A learning rate indicates the fractional reduction in the cost for each
doubling of cumulative capacity. For this analysis, a learning rate is applied at a component level made up of three
individual factors, based either on UK only or global deployment:
• Technology innovation
• Supply chain competition
• Economies of scale
The learning rate is applied only once 1GW installed capacity has been reached as there is expected to be limited
learning applicable to all first-generation projects based on the wide range of substructure and project types
being pursued in the 2020s. Learning rates have been estimated and applied to project costs. These draw on
innovation roadmaps published by the Offshore Wind Innovation Hub1 and the European Technology Innovation
Platform on Wind Energy (ETIP Wind)2 as well as our understanding of key supply chain dynamics. The weighted
average learning rate is 9.5%. Cost reduction has also been assessed for a scenario with limited innovation, which
results in a weighted average learning rate of 5.9%.
5.3 TRANSMISSION CHARGES
Offshore wind projects currently pay two electricity transmission network charges - The Balancing Services
Use of System (BSUoS) charge reflects the costs of balancing the system and the Transmission Network
Use of System (TNUoS) charge covers the building, operation and maintenance of the transmission system.
TNUoS charges are dependent on where in the country a generator is connecting to the grid, and charges are
consistently higher in Scotland.
1 https://offshorewindinnovationhub.com/
2 https://etipwind.eu/roadmap/
10 ORE.CATAPULT.ORG.UKThe nine FOW zones identified are spread across four National Grid generation zones. The TNUoS charges
applied in the analysis are based on 2019/20 rates, however these rates are expected to increase over the next
five years based on the recently published Five Year View3. These price increases hit particularly hard on the East
Aberdeenshire zone (Relevant for FOW zones A – D). If the 2025/26 forecast charge of £30.23 per kW is used
instead of the 2019/20 rate of £15.64 per kW, this increases LCOE by up to 6.8% for sites being constructed in
the mid-2030s. The proportional effect is much greater in the future as costs are expected to reduce in all other
areas whilst TNUoS increases.
Notably, this year’s five-year forecast has higher future costs that the previous year’s forecast. If forecasts continue
to change, the unknown cost of transmission charges proves a considerable risk for project developers locking in a
fixed strike price and may result in higher margins to protect returns against rising transmission charges.
5.4 COST REDUCTION FOCUS AREAS
A small number of cost reduction opportunities stand out, which can have a large impact on areas which account
for a large share of project costs:
5.4.1 Substructure manufacture
FOW substructures to date have been largely bespoke with a wide range of designs. Advances in fabrication and
assembly facilities and processes, such as advanced manufacturing and robotic welding, along with targeted port
investment will have a significant impact on project cost.
5.4.2 Mooring line design and installation
Improvements in design standards, standardisation of components, use of novel materials (including synthetic
rope) and optimisation of array layouts all have cost reduction potential. A more integrated design interface
between anchors, mooring system and substructure would enable further benefits and speed up installation and
major repair operations.
5.4.3 Minor repairs and preventative maintenance
FOW is expected to benefit from similar innovations as bottom-fixed (e.g. increased automation, UAV’s, drones,
etc). This is particularly valuable to FOW as many of the sites are in less accessible environments than bottom-
fixed turbines. Modifications need to be developed for positioning systems for CTVs, service operations vessels
(SOVs) and helicopters to account for the motion of floating wind turbines to minimise personnel risk.
5.4.4 Development costs
Front end engineering design costs could rapidly decrease as numerical models are improved and design
processes are more streamlined and standardised. Some development costs, such as stakeholder engagement,
surveying and consenting have high fixed costs which will reduce significantly when spread across larger projects.
5.4.5 Array cables
Design of cable connection systems may be optimised to reduce the time taken to connect and disconnect
cables. Cable design may also be improved to withstand the different loadings dynamic cables are under in site
conditions at FOW sites. Higher voltage array cables will be beneficial for projects using higher rated turbines to
increase the number of turbines on strings. This will require innovation in both static and dynamic cable design.
3 https://www.nationalgrideso.com/charging/transmission-network-use-system-tnuos-charges
11 ORE.CATAPULT.ORG.UK5.5 VISIBLE PROJECT PIPELINE
The impact of having visibility of a future project pipeline cannot be understated. CfD auctions have brought
prices down by reducing revenue risk in a project, allowing project developers to proceed with a capital-intensive
project with a long-term, low-risk return. In the same way, project visibility will assist the supply chain to invest in
new facilities to support the construction and maintenance of FOW sites.
Many of the highest impact opportunities require significant private investment which can only be realised if
there is a clear demand through a succession of projects. Investment in substructure fabrication as highlighted
above, could create new job opportunities as well as reducing costs by embracing innovation to support both UK
projects and exporting globally.
Along with investment in innovative facilities, a visible pipeline may also bring new supply chain players to the
market, increasing competition and providing additional supply chain capacity to serve a rapidly growing market.
Projects need to be spread evenly, both in timeline and in geographic diversity, to avoid bottlenecks that may
increase competition for limited manufacturing and port facilities. This could also have the effect that facilities
are used at a high capacity, which will reduce the cost of running the facility and reduce staff turnover rather than
experiencing peaks and troughs.
12 ORE.CATAPULT.ORG.UKDocument History
Revision Date Prepared by Checked by Approved by Revision History
6. COST
1 OF CAPITAL 02/12/2020 Miriam Noonan Ralph Torr Ralph Torr
6.1 COST OF CAPITAL OVERVIEW
Cost of capital is considered in this study as the weighted average cost of capital (WACC) applicable to financing
UK floating wind projects. All values modelled and quoted for the study are in real terms, consistent with the
basis of the cost estimations.
6.1.1 Resulting cost of capital estimates for UK floating offshore wind
The resulting costs of capital for both UK floating offshore wind and UK bottom-fixed offshore wind are shown
together with the relevant deployment profiles in Figure 5. Note that the UK deployment profiles shown are
an average of the 75GW (8GW) and 100GW (16GW) scenarios to show a single trajectory to avoid further
complicating the chart.
Bottom-fixed vs Floating Offshore Wind Cost of Capital Estimates and Forecasts
16% 60
14%
50
Cumulative deployment (GW)
12%
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Cost of capital
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UK cumulative OSW deployment (GW) UK cumulative FOW deployment (GW) Cost of debt (real) bottom-fixed
Cost of equity (real) bottom-fixed WACC (real) bottom-fixed Cost of debt (real) floating
Cost of equity (real) floating WACC (real) floating
Figure 5: Bottom-fixed vs floating offshore wind cost of capital
This is showing that by the time the first commercial-scale projects (500MW +) could be deployed in the UK
around 2029-2030, we expect WACC of ~5.5%, reducing to a steady state of 4.2% by 2033 with around 4GW
installed capacity.
This shows a clear acceleration in the reduction of cost of capital for floating offshore wind compared to bottom-
fixed. The main factor driving this is that floating offshore wind can “piggy-back” on much of the technology,
operational and asset management experience already demonstrated by bottom-fixed offshore wind (eg. same
turbine technology) and by offshore oil & gas. Much of the learning is transferable between industries and the
risks are much better understood today than 10 years ago for bottom-fixed offshore wind.
13 ORE.CATAPULT.ORG.UK7. COST REDUCTION
7.1 COST REDUCTION PROFILE
The project deployment and cost profiles were modelled to estimate the cost reduction potential of FOW in the
UK in the context of the 75GW(8GW) and 100GW(16GW) UK deployment scenarios described in section 4.2,
the learning rate assumptions described in section 5.2 and the cost of capital assumptions described in section 6.
A summary of the cost reduction impact is given below.
• Project life is assumed to increase from 25 years to 30 years in 2030. This reduces LCOE in 2030 by 6%
versus retaining the 25-year project life assumption
• Capex reduces 65% between 2027 and 2040 in the 75GW (8GW) scenario, and 64% in the 100GW (16GW)
scenario in the same timeframe. Although we would expect cost reduction to be higher in the scenario with
higher deployment, it is also impacted by the site parameters of the projects being deployed. That is, in the
Contents
100GW (16GW) scenario, the pace of deployment means challenging sites will be built out earlier, which
partly offsets the greater learning rate-driven reductions
• OPEX reduces 36% from 2027 to 2040 in the 75GW (8GW) scenario, and 32% in the 100GW (16GW)
scenario
3.0
in the same timeframe, due to the
UKsame drivers as
FOW Deployment CAPEX
- Scenarios
20
• Net capacity
2.5
factor generally increases over time due to higher turbine ratings. However, it is also very
18 site
16
dependent, impacted by average wind speed, metocean conditions at site and distance to onshore 14 O&M
GW - cumulative
2.0
facilities. Net capacity factor increases by 2.9% from 2027 to 2040 in the 75GW (8GW) scenario, and 12 6% in
GW - annual
the 100GW1.5
(16GW) scenario driven by especially high wind speeds at Site B in 2039 10
8
1.0
The LCOE profiles are compared with the BEIS low wholesale electricity price forecast in 2020 terms in6 Figure 6.
4
0.5
2
0.0 0
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
UK 75GW (8GW FOW) - annual UK 100GW (16GW FOW) - annual UK 75GW (8GW FOW) - cumulative UK 100GW (16GW FOW) - cumulative
UK FOW cost Reduction vs BEIS forecast low wholesale price - Scenarios
140
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₤/MWh (2020)
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60
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2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
BEIS Low Prices UK 100GW (16GW FOW) with innovation UK 100GW (16GW FOW) - limited innovation
UK 75GW (8GW FOW) with innovation UK 75GW (8GW FOW) - limited innovation
Figure 6: UK FOW cost reduction vs BEIS forecast wholesale electricity price
14 ORE.CATAPULT.ORG.UKDeployment is a critical cost reduction driver in the early commercial phase of the technology. LCOE is 20% lower
in 2030 in the 100GW (16GW) scenario versus the 75GW (8GW) scenario. By 2040, the LCOE is roughly the
same in the two deployment scenarios.
Whilst early cost reduction is largely deployment driven, longer term cost reduction is achieved through higher
innovation. Without innovation, LCOE is approximately 10% higher in 2030 and 20% higher in 2040 in both
scenarios.
LCOE for the 75GW scenario only fully converges with the 100GW scenario in the late 2030s. There may be a
brief earlier convergence around 2032 following 2 years of similar deployment levels but LCOE diverges again,
driven by slower deployment in the 75GW scenario, with a single 915MW project being installed between
2033 to 2035 versus 3,670MW in the same time frame in the 100GW scenario. The learning rate impact of this
additional deployment yields a 2% reduction in LCOE. Convergence is linked to a steady UK pipeline (although
still lower in the 75GW / 8GW FOW scenario), illustrating the importance of pipeline consistency as well as
volume, particularly with the UK having up to 20% of global deployment in 2040.
This analysis considers cost reduction alone. When considering both delivering Net Zero and UK GVA, an
accelerated UK deployment rate in the early 2030s is key, as other FOW markets rapidly commercialise. Rapid
deployment of FOW in the UK is key to reducing the cost of FOW in the UK in the short term (2020-2035). It
is also likely to be key to maximising UK GVA in the medium and long term. In particular, the significant export
opportunity may be lost if the UK is a slow starter in the industry.
8. CONCLUSIONS
This report was commissioned by the Floating Offshore Wind Centre of Excellence to
develop a number of Floating Offshore Wind cost reduction pathways to subsidy free
levels. These pathways were developed within a specially developed FOW cost reduction
pathways model. This model has produced the outcomes outlined in this report, but also
provides a resource for use in future project activity.
SCALE OF DEPLOYMENT
The UK has a large marine expanse with attractive site conditions for FOW, spread across several regions. Based
on GIS mapping, we have identified a potential near-term pipeline of 19.3GW.
Detailed near-term UK FOW development profiles have been estimated within the context of three UK offshore
wind deployment scenarios: 75GW, 100GW and 150GW total offshore wind by 2050.
• The 75GW scenario assumes installed FOW capacity of 8.1GW by 2040, at an average annual rate of
730MW per year from 2029. The 75GW scenario is stop-start in nature and may not provide the continuous
pipeline required by supply chain and project developers to invest, scale up and skill up, particularly when
the regional distribution of projects is considered
• The 100GW scenario assumes 16GW could be deployed by 2040 with an average annual rate of 1.3GW
per year from 2028 (increasing to 1.5GW per year by 2035 and up to 3GW per year in 2040). This provides
a smooth deployment trajectory, and utilises almost the full identified pipeline (of most cost-effective
development areas identified in this study)
15 ORE.CATAPULT.ORG.UK• The 150GW scenario assumes the same FOW deployment profile as the 100GW scenario to 2040, with
accelerated deployment in the 2040s. This is expected to include a higher proportion of non-grid connected
projects, used as a power source for hydrogen production.
Note, the role of FOW in the 100GW (40% FOW) and 150GW (60%) scenarios is significant and highlights the
importance of FOW for the UK should >100GW of offshore wind be required to deliver net zero. Achieving
100GW or 150GW of offshore wind will require significant developments in the wider energy system, including
large-scale hydrogen production and increased inter-connection.
A single FOW development scenario has been assumed for global deployment, reaching 9GW deployed in 2030
(including the UK) and 71GW in 2040.
COST REDUCTION
Cost reduction in UK FOW will happen much faster than it did in bottom-fixed wind. It will benefit from using
state of the art turbine technology and O&M innovations. It will also benefit from greater levels of competition
for project financing, particularly in the development phase. This, in combination with the maturity of the broader
offshore wind sector means the industry will have much lower cost of capital than bottom-fixed offshore wind at
the same stage of commercial maturity. By the time the first commercial-scale projects (500MW +) are deployed
in the UK around 2029-2030, we expect WACC of ~5.5%, reducing to a steady state of 4.2% by 2035.
UK FOW costs are expected to reduce quickly, driven by deployment in the early years. LCOE is 20% lower in
2030 in the 100GW scenario versus the 75GW (8GW) scenario. It should be noted that, over time, UK FOW
becomes a decreasing proportion of global deployment and so cost reduction on the whole is driven more by
global than UK deployment in the long term
When looking at FOW LCOE in isolation, accelerating deployment above the 75GW (8GW) scenario has a limited
impact on cost reduction in the medium and long term. By the mid-2030s, costs are comparable in the two
(75GW and 100GW) scenarios and are largely driven by available site characteristics. However, in the short-term
deployment in line with the 100GW (16GW) scenario will result in costs reducing faster and importantly provide
a consistent pipeline of project activity for the supply chain (encouraging long term investment in the supply
chain, innovation and driving efficiencies). In addition, when UK GVA is considered this faster pace of deployment
is critical in developing and maintaining a market leading position for the UK supply chain in FOW (attracting
associated investment in innovation, supply chain capability etc).
Whilst innovation makes a contribution to LCOE reduction in the short term, its real impact is on longer term
cost reduction. Without innovation, LCOE is approximately 10% higher in 2030 and 20% higher in 2040 in all
scenarios. This innovation will also be key to maximising UK GVA from floating offshore wind, through higher UK
content in UK projects and exports
Accelerating UK FOW deployment, mainly through larger capacity projects, from the point of subsidy-free, will
maintain cost reduction momentum and, depending on the support regime in place in the 2030’s, could allow
repayment to the LCCC from projects operating at sub-wholesale prices.
16 ORE.CATAPULT.ORG.UK9. RECOMMENDATIONS
The following recommendations are made with respect to supporting rapid cost
reduction in UK FOW, whilst ensuring the industry also plays a key role in driving UK
economic growth and delivering net-zero:
• Rapid deployment of FOW in the UK is key to reducing the cost of FOW in the UK in the short term (2020-
2035). It is also likely to be key to maximising UK GVA in the medium and long term. The FOW industry in
the UK should be supported to grow rapidly, alongside establishing a clear long-term vision for the growth of
the industry.
• Early support for technology innovation should be provided as it will drive long-term cost reduction and
maximise UK content in FOW projects. It will also be a key driver of UK GVA through exports of products
and services. This is particularly important for substructure fabrication and assembly processes, mooring
system and cable system design and manufacture and operations and maintenance.
• An offshore leasing round should be established in the next two years to facilitate access to the most cost
effective FOW project areas in England and Wales, specifically the Celtic Sea and North East England.
• Of the pathways considered in this analysis, it is recommended the 100GW pathway should be pursued
in the short-term until subsidy-free LCOE is estimated to be achieved; beyond this, deployment should
be managed to ensure offshore wind is deployed most cost effectively to deliver net-zero, whilst
simultaneously maximising UK GVA.
• Existing and new supporting policies should be actively managed to spread projects evenly to avoid
competition for limited supply chain facilities and enable manufacturing and port facilities to run at a high
capacity thereby reducing their running costs. This can be achieved through establishing a long-term vision
for the industry and managing CfD (as relevant) allocation rounds in a regular and synchronised cycle.
Providing visibility of a future project pipeline will also encourage supply chain investment in innovation and
infrastructure and increase supply chain competition by attracting new players.
17 ORE.CATAPULT.ORG.UKCONTACT US ENGAGE WITH US
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